This paper describes the rationale, justification and benefits associated with the deployment of wired-pipe telemetry drillstrings at Occidental of Elk Hills, Inc. (OEHI) in Kern County, California. Recent technological advances in Measurement While Drilling (MWD) systems, Logging While Drilling (LWD) systems, and wired-pipe telemetry systems have overcome historical data bandwidth issues enabling real-time acquisition of critical data streams. These data sets include: continuous annular pressure for equivalent circulating density (ECD) management; vibration diagnostics for drilling optimization; instantaneous downlink commands to Rotary Steerable Systems (RSS) that aide in eliminating secondary non-productive time (NPT) and enhancing directional control; and memory quality formation evaluation measurements to improve reservoir navigation and wellbore placement. With this new wealth of data, onsite drilling personnel, geoscientists, and office engineering staff are able to make real-time decisions that serve to enhance wellbore quality and reduce overall costs. Utilizing wired-pipe to its full potential has helped to deliver an average drilling time savings of 10%. Introduction The benefits of drilling dynamics and formation evaluation from MWD and LWD tools are well known. However, these systems are impacted by bandwidth limitations which restrict the amount of data that can be transmitted to surface in real time. Recent advances in technology have addressed this issue. At the OEHI asset, Oxy and the service providers worked together to evaluate the application and benefits of deploying wired-pipe transmitted data in a land based environment. The technology was tested in combination with multiple downhole LWD and RSS tools. The system was tested in both a 5-in. tubular/mud-based and a 4-in. tubular/foam-based environment. Benefits in the Use of Wired-Pipe Telemetry One of the major challenges in a fast rate of penetration (ROP) drilling environment is transmitting all the required data to surface in a timely manner. When mud-pulse telemetry or electromagnetic data transmission is used, a large amount of this data is stored in memory and downloaded after the tool is tripped out of the hole. The drawback to this system is the lag time in receiving and processing the downhole measurements on the surface. As downhole acquisition technology continues to advance, these measurements are requiring additional bandwidth. This reduces the data density of mud-pulse telemetry points transmitted to surface while drilling, thus, making real-time interpretations and decisions challenging. In order to make an interpretation from a full data set, the operators must wait for the bottomhole assembly (BHA) to be tripped out of the hole and the memory data to be downloaded.

Horizontal drilling has been the industry standard for oil production wells in the North Sea for decades. Significant improvements have been made in the precision of directional drilling by rotary steerable systems (RSS), nevertheless there remain opportunities to mitigate operational challenges in complex drilling environments. One such challenge is the occurrence of hard stringers interbedded between soft sandstone and limestone formations within the reservoirs. The interaction between the bit and hard stringers at the interfaces can lead to a deflection of the bit, resulting in high local doglegs (HLDs), and excessive static loads unless mitigation actions are triggered in a timely fashion. Operational parameters have to be adjusted during hard-stringer drilling, but are also constrained in the underlying formation to avoid HLDs and guarantee bit and BHA integrity. The key to efficient stringer drilling presented here is a consistent, timely and reliable method of detecting stringers. This is enabled by a fit for purpose stringer detection algorithm embedded in a measurement-while-drilling (MWD) tool for vibration and load measurements, combined in a systems approach with an automated surface system. Different indicators such as vibrations, loads and ROP that are traditionally used for stringer detection have been analyzed in the development phase of the algorithm. High-frequency torsional oscillations (HFTO) have been found to be a leading indicator for stringer drilling: HFTO is a torsional vibration phenomenon with high frequencies (50Hz-450Hz) and is only excited by the bit-rock interaction in hard formations. The HFTO amplitudes in sand/lime stones and calcite stringers show well separated distributions. Finally, HFTO is unique in that it is not directly affected by the driller, or due to other downhole dysfunctions, e.g. compared to a change in weight on bit (WOB) which may be caused by a surface parameter change or a stabilizer. The physics-based algorithm embedded in the MWD tool combines tangential acceleration and dynamic torque measurements to calculate the maximum HFTO load in the BHA. A stringer is identified if an HFTO maximum amplitude threshold is exceeded and the energy is localized in one frequency. The downhole indicator is aggregated to a 1-bit value (stringer/no stringer) that enables a high telemetry update rate and thereby a timely reaction at surface. The stringer indicator and advice are displayed to the driller and are actively used for stringer drilling. The paper describes the technology as well as the operational setup, and experience from the first field deployments. By using the new technology, the driller can react faster to any stringer and use appropriate parameters to avoid costly HLDs. First field deployments demonstrate a significant improvement in invisible lost time (ILT) caused by deflections of the bit, resulting in a considerable reduction in well delivery costs.

Drilling hard stringers that are erratically distributed in an underlying rather soft formation is challenging from different perspectives. An unforeseen change of the drilled formation from soft to hard and dense rock can cause impact damage to the bit, deflect the bottom-hole assembly (BHA), result in high bending loads, increase vibration, and cause wear/tear on BHA components. If not properly managed, this leads to non-productive time (NPT) and increased maintenance costs. Further, a deflection caused by a stringer away from the planned well path that is detected late results in high local doglegs (HLD) and requires time-consuming correction through reaming with invisible lost time (ILT). Recently, a stringer detection method based on vibrations, namely high-frequency torsional oscillations (HFTO), has been presented. A case study with 21 sections in the North Sea based on this solution is shown that demonstrates a reduction in ILT by 80%. The system is based on a timely and reliable detection of stringers, an optimized mud pulse telemetry scheme, and an automated advisory system. The downhole algorithm embedded in a measurement while drilling tool is consistently interpreting HFTO based on tangential acceleration and dynamic torsional torque measurement. By defining thresholds for the amplitude and the localization with respect to frequency content of HFTO, the algorithm results are translated into a binary value with 1 – stringer currently drilled or 0 - no stringer is drilled. The low bandwidth consuming 1-bit value and downhole measured bending moment are sent in 10 to 15 second intervals to the surface by mud pulse telemetry. Once the stringer is detected, the bending moment data is closely monitored to react correctly and efficiently to a stringer in different scenarios. This solution is discussed in a case study in Norway covering 21 sections with and without the system deployed. The offshore application is challenged by frequently occurring stringer layers and nodules of different geometry. Based on the stringer content, the reaming time has been typically high in this application. The system, however, enabled a timely detection of the stringers and an optimal stringer drilling enabled by the frequently sent bending moment information. Therefore, stringer drilling was done without having to pull off-bottom frequently and ream the transition area between soft and hard formation thereby saving time and reducing wear on the BHA and drill pipe, ultimately ending up with a smoother/straighter wellbore. By using the system, a faster reaction to any stringer and the use of appropriate parameters to avoid costly HLDs are achieved. The case study demonstrates a significant and consistent improvement in ILT. The reaming hours per 1000 m as a benchmark have been reduced from 2-5 hours without to 0.3-0.6 hours with the system resulting in an average saving of 12 hours per reservoir section.